The present invention relates to fluids useful as subterranean viscosified treatment fluids, and more particularly, to novel polycarboxylic acid copolymer gelling agents and viscosified treatment fluids comprising these gelling agents, and their associated methods of use and manufacture.
As used herein, the term “treatment fluid” refers to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof. Viscosified treatment fluids are used in a variety of operations in subterranean formations. For example, viscosified treatment fluids have been used as drilling fluids, fracturing fluids, and gravel packing fluids. Viscosified treatment fluids generally have a viscosity that is sufficiently high, for example, to suspend particulates for a desired period of time, to transfer hydraulic pressure, and/or to prevent undesired leak-off of fluids into a formation. Viscosified treatment fluids are often used in fracturing operations. Hydraulic fracturing is a technique for stimulating the production of desirable fluids from a subterranean formation. The technique normally involves introducing a viscosified treatment fluid through a well bore into a formation at a chosen rate and pressure to enhance and/or create a fracture in a portion of the formation, and placing proppant particulates in the resultant fracture, inter alia, to maintain the fracture in a propped condition when the pressure is released. The resultant propped fracture provides a conductive channel in the formation for fluids to flow to the well bore. The degree of stimulation afforded by the hydraulic fracturing treatment is largely dependent on the conductivity and width of the propped fracture.
Viscosified treatment fluids (e.g., fracturing fluids) that are used in subterranean operations generally are aqueous-based fluids that comprise a gelling agent, which may be crosslinked. These gelling agents may be biopolymers or synthetic polymers. Common biopolymer gelling agents include, e.g., galactomannan gums, cellulosic polymers, and other polysaccharides. Because of their cost and effectiveness, biopolymers are most commonly used. However, in high temperature applications, these gelling agents can degrade, which can cause the viscosified treatment fluid to prematurely lose viscosity. Various synthetic polymer gelling agents have been developed for use in viscosified treatment fluids. While some synthetic polymers have achieved some success, there are continuing needs for improved synthetic gelling agents that are stable at relatively high temperatures (e.g., above 300° F.).
The viscosity of a viscosified treatment fluid may be increased by crosslinking the gelling agent in the fluid. Gelling agent molecules are typically crosslinked through a crosslinking reaction with a crosslinking agent that has been added to the treatment fluid. These crosslinking agents generally comprise a metal, transition metal, or metalloid, collectively referred to herein as “metal(s).” Examples include boron, aluminum, antimony, zirconium, magnesium, or titanium. Generally, the metal of a crosslinking agent interacts with at least two gelling agent molecules to form a crosslink between them. Under the appropriate conditions (e.g., pH and temperature), the crosslinks that form between gelling agent molecules may increase the viscosity of a viscosified treatment fluid.
One type of fracturing fluid has been developed for use in deep, high temperature wells comprises a crosslinked synthetic gelling agent. The gelling agent is a high molecular weight copolymer of 60% to 78% acrylamide and 22% to 40% potassium acrylate crosslinked with a titanium or zirconium compound. In preferred embodiments, the copolymer comprises about 30% of the acrylate monomer to achieve optimal crosslinking. Unfortunately, an acrylate concentration this high may cause the gelling agent to have poor salt tolerance in subterranean applications, and therefore, these fluids are not optimal in higher pressure and temperature deep wells.
Viscous foamed treatment fluids have been used in conventional fracturing operations. Benefits of using foamed treatment fluids in such operations include a reduced risk of: leak-off of the fluid into a permeable formation, and damage to the formation by polymer residue deposits. Also, because a foamed treatment fluid is less dense than a conventional treatment fluid, flow back of the fluid may occur.
The gases typically used in forming foamed treatment fluids usually are nitrogen, carbon dioxide, and mixtures thereof. Generally carbon dioxide is more economical for wells having greater depths and correspondingly higher pressures and temperatures. Carbon dioxide can be pumped at a lower wellhead pressure than nitrogen because it has a higher density than nitrogen at similar conditions.
Carbon dioxide foamed fracturing fluids heretofore have been utilized in subterranean zone having temperatures up to about 400° F. However, the viscosity of a foamed fracturing fluid is at least partially dependent upon the liquid phase thereof, and the viscous liquids utilized heretofore have generally been unstable at temperatures above about 300° F. Aqueous gelled liquids containing gelling agents such as guar, hydroxypropylguar, and carboxymethylhydroxypropylguar lose viscosity by thermal thinning, and become hydrolytically unstable above about 350° F. Also, at 350° F. and above, the heretofore used carbon dioxide foamed treatment fluids have not demonstrated desirable proppant particle carrying capability.